Well treating method using relatively high fluid loss treating liquids



June 6, 1967 .1. A. KNOX ET AL WELL TREATING METHOD USING RELATIVELYHIGH FLUID LOSS TREATING LIQUIDS Filed Feb. 28, 1966 w m m M M U H m 5 Mw M M e m W T 3 a Fluid g n C U d o r P Zone Well Bore Fracture FlowLines Equipressu're k m. M

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nd ./E AH M O mm w United States Patent M 3,323,595 WELL TREATHNG METHODUSING RELATIVELY ll-llGH FLUTE LOSS TREATING LIQUIDS John A. Knox,Duncan, Okla, and Fred H. Adcock, J13, Perryton, Tern, assignors toHallihurton Company, Duncan, (Edda, a corporation of Delaware Filed Feb.28, 1966, Ser. No. 534,581 6 Claims. (Cl. 16642) ABSTRACT OF THEDISCLDSURE A method of treating wells for providing a continuing orprolonged treatment of a desired type by introducing into a producingformation a thin, high fluid loss treating liquid under a pressuresufficiently great to cause the treating liquid to be substantially lostto a fracture face near the well bore. The treating liquid issubsequently slowly produced back with the well fluids.

This application is a continuation-in-part of application Ser. No.278,327 filed Mar. 6, 1963, now abandoned, and is entitled to all thebenefits provided by law of said earlier filed application.

The present invention relates to a new and improved method of treatingwells and more especially to a method wherein a relatively high fluidloss treating liquid of a desired type is placed in at producingformation and slowly produced back with the produced fluids.

In modern oil and gas Well treating practices, it has become veryimportant to provide prolonged benefit from single treatments for wells,whether such treatments be for paraflin control, scale control,corrosion control or other. One way in which paraffin inhibition andcontrol is provided over a period of time is illustrated in US. PatentNo. 3,051,653. In such well treatment method, certain slowly solubleparafiin inhibiting solid chemicals are placed in the well or back inthe formation, and as the well fluids are produced, they are treatedwith the chemicals. The treatments have proved to be very satisfactory,but solubility rates and melting points may be coordinated with wellconditions to produce the best results.

It is therefore an important object of the present invention to providea new and improved method of inhibiting or controlling the formation ofparaflin on surfaces past which hydrocarbons flow.

Another important object of the present invention is to provide a newand improved method of inhibiting the corrosion of well equipment orother materials used in wells.

Still another important object of the present invention is to provide anew and improved method of controlling or inhibiting the deposition ofscale and like materials in wells and on the equipment therein.

Another object of the present invention is to provide a new and improvedmethod of adding surfactants for changing or maintaining the wettabilityof a formation, breaking emulsions, forming emulsions or other purposesor adding other well treating chemicals to the well fluids as they areproduced.

Still another object of the present invention is to provide a new andimproved method of adding emulsion breakers to well fluids in thosewells which produce natural emulsions.

A further object of the present invention is to provide a new andimproved method of adding chelating or se- Patented. June 6, 1967 Iquestering materials to well fluids as such fluids are produced toprovide aprolonged treatment of the well fluids.

Yet a further object of the present invention is to provicle a new andimproved method of treating well fluids, wherein a plurality of treatingliquids may be simultaneously added to the well fluids as they areproduced for providing a variety of treatments to the well fluids asdesired.

Other objects and advantages of the: present invention will become morereadily apparent from a consideration of the following description anddrawings wherein:

FIG. 1 is a vertical section of a well bore and fracture therein,schematically illustrating the location of fluids after injection; and

FIG. 2 is a vertical section of a well bore and fracture therein,schematically illustrating the fluid flow profile during production andafter treatment.

Although many different liquids have been injected or introduced intooil and gas wells and the like for a variety of reasons, none haveheretofore been injected for the purpose of providing a long feed backthereof or a prolonged treatment of the well therewith. Under the priorart teachings as exemplified by the paraifin inhibition method of US.Patent No. 3,05 1,65 3, slowly soluble solid materials have been used toprovide prolonged or continuous treatments of a well. Solubilities andmelting points must always be taken into consideration when using suchsolid materials.

In placing the treating materials into a fracture in a well formation,it has been discovered that a longer feed back may result if thetreating material is completely dissolved in oil or other solvent, thanif such material is slowly soluble and remains in the fracture.

The treating solution of the present invention is preferably a highfluid loss liquid and is displaced in a well formation at a ratesuflicient to fracture the formation, but which will also permit thetreating liquid to be lost of the face of the fracture and into theformationwithin the first few feet of the fracture. In carrying out thepresent invention, it is preferable. that the fracture be a horizontalradial one. s.

The method of the present invention may also be used with verticalfractures, but shorter feed back times of the treating fluid may result.i

Referring now to the drawings, the flow patterns of fluids injected intoa well during fracturing and the pro duction of fluids from the wellafter fracturing is completed are schematically illustrated. i

In FIG. 1 a well bore 10 is shown with a horizontal fracture 12extending therethrough. The fracture 12 is i1- lustrated as beingsufficiently long to show the pattern of fluids injected into the wellbore 10 and fracture 12.

The treatingwfluid or fracturing fluid containing the treating agent,paraflin inhibitor, bactericide, scale preventative, corrosioninhibitor, emulsion breaker, surfactant, chelating agent or other isinjected or pumped into the well bore 10 at a sulficient pressure andrate to create the horizontal fracture 12. The treating fluid 14 ispreferably a highfiuid loss liquid as defined hereinbelow and is alsointroduced into the well bore 10 and fracture 12 in such manner that itis substantially lost to the face of the fracture and into the formation15 within the first few feet of the fracture. This may be readily seenin FIG. 1 wherein near the end of the .fracture at point a, the treatingfluid 14 has just barely entered the formation and wherein near thebeginning of the fracture at point b, the treating fluid has beeninjected relatively far into the formation.

The treating fluid 14 may be further displaced into the formation by theinjection of either additional treated fluid or untreated fluid 16. Theuntreated fluid should preferably be of low fluid loss to limitdisplacement of fluid 14. The amount of fluid injected into theformations will govern the extent the fluids 14 and 16 are extended intothe formation 15, but the flow pattern as observed in FIG. 1 will existwithout regard to the amounts of fluid injected into such formation 15.

It can, therefore, readily be seen that the treating agent or treatingfluid 14 reaches its maximum penetration into the formation or producingsand 15 at or near the well bore.

It can also be appreciated that the treating agent need not bedistributed throughout the fracturing fluid, but may be placed ordispersed in only the first portion or spear head of fracturing fluidinjected into the Well. Economics, size of formation to be treated, andtype of treatment to be made will largely control the amount of treatingagent used in this operation.

After the fluids have been introduced into the formation and the wellhas been placed on production, the fluids injected into the well and thenatural well fluids will be produced from the formation, through thefracture and into the well bore in a particular pattern.

This pattern may best be seen in FIG. 2 wherein fluids from theproducing zone 20 enter the fracture 12 as illustrated by the flow lines21.

The dotted lines 23 illustrate the pressure profile along each of theflow lines 21. From these flow lines 21 and equi-potential lines 23, itis easily seen that as fluids are produced from the zone 20, theheaviest rate of flow is near the end of the fracture 12 at a point c,and that there is little flow of fluids from a point 0., near the wellbore 10 or beginning of the fracture 12.

The treating liquid which has been lost to the formation nearest thewell bore Will therefore be slowly produced back with the producingfluids. As only a few parts per million are required of most treatingagents to provide an effective control over the problems, a continuingcontrol of the problem is maintained over a long period of time.

The amount of treating agents required or needed for a particular job isreadily determined by one skilled in the art.

Two articles have been written by Dr. H. K. van Poollen which explain indetail the pattern of fluid production upon fracturing a formation.These articles are entitled Productivity Permeability Damage inHydraulically Produced Fractures and Do Fracture Fluids DamageProductivity presented at the Spring Meeting of the SouthwesternDivision of Production, American Petroleum Institute in Dallas, Texas,March 6-8, 1957, and published in the May 27, 1957 issue of The Oil andGas Journal, respectively.

A high fluid loss liquid is defined herein as a liquid having aneffective E value (E of 0.003 ft./min. or higher as explained indetailed hereinbelow.

The leak-off rate of an injected fluid to any given area is dependent oneach of the following: differential pressure from fracture to formation,fluid viscosity, time of exposure to fluid (decreasing as the squareroot of time), formation permeability, porosity, saturationclassification of the producing formation, and the compressibility offormation fluids.

Rate of fluid leak-off may be mathematically described by either theterm E which describes the viscous resistance to flow into permeabilityor by E which describes the resistance to penetration due to the lowcompressibility of formation fluids. In saturated formations E is usedto calculate leak-off rates due to a combination of B and E These termsare mathematically determined or described by the following.

1 1 l Tar-22%;

Where:

=formation porosity as a decimal K=formation permeability, darcys (1darcy=1000 millidarcies) /J.=ViSCOSlty of injected fluid at bottom holetemperature,

cps.

AP=ditferential pressure, p.s.i. (bottom hole treating pressure lessreservoir pressure) C =reservoir fluid compressibility factor, p.s.i.

Formation conditions will, to a great extent, control the limits ofthese values, and thus require variations in the treatment method toobtain the proper treating fluid penetration profile for desiredprotection.

The penetration profile is then determined based on the describedexample conditions by the solution of a stoichiometric material balancein which the injected volume equals the loss volume to a given area plusthe volume of generated fracture based on an incremental time analysis.The width of the fracture during injection can be calculated by acceptedmethods based on rock properties, fluid properties, volume injected andrate of injection. The results of this analysis determine the rate offracture generation, rate of leak-off and total leak-01f volume to anyincrement of area within the generated area.

Based on this data, the volumetric treating fluid contribution to thetotal production from any increment of fracture area can be determined.

This permits the calculation of feed back rate, concentration oftreating chemical within the produced fluid, changes in concentration oftreating chemical with time and the maximum time over which protectioncan be expected.

From these calculations suita-ble volumes of injection fluid, rates ofinjection or techniques can be determined to provide the desiredprotection requirements for particular formation conditions.

An illustration of the determination of E for a particular job andformation conditions is set forth in Example I.

Example I.]ob and formation conditions Formation permeability-20 md.=.2darcy Formation porosityl percent: 0.15

Reservoir fluid compressibility factor1 x p.s.i.- Differential pressureduring injection2000 p.s.i.g. Viscosity of injection fluid1.0 cp.

Injection rate desired2 b.p.m.

Injection volume3000 gallons Producing rate of oil following treatmentb.p.d. Formation saturated Horizontal fracture induced For theseparticular formation conditions, an E of 0.120 ft./min. was calculatedwith the value of E being 0.013 ft./min. The resulting E for thesaturated reservoir was determined to be 0.0117 ft./min.

For the conditions cited in this example penetration distances areillustrated for increments of area from the well bore zero ft. to anarea of 1947 ft. generated at a time of 10 minutes. The losses to theseareas are based on the total pumping time of 35 minutes, The profile andvolume lost to the area increments beyond feet were not calculated inthis example. This could be done by determining the area exposed in eachminute of pumping (A thru A thereby determining the period of time inwhich fluid is lost to that area. This time is the pumping time minusthe time required before exposure. This time would then determine thevolume lost to that area and the resulting profile for calculation offeed back rate.

The subsequent solution of this problem in the described manner for onlythat portion of mateiral contained in the area described above indicatesa feed back rate of 2.52 gallons per day for 498 days followed by a feedback rate of 0.84 gallon per day for an additional 312 days. Thecalculated protection time would have been in excess of this time hadthe solution been carried out for the total area generated in 35minutes.

The following variables will alter the calculated protection time.

(1) Formation permeability (2) Formation porosity (3) Differentialtreating pressure (4) Rock properties (5) Fracture orientation (6) Fluidviscosity (7) Production rate following treatment Treatments can bedesigned for pre-determined periods of protection in the same generalmathematical manner as shown above.

The present invention may be utilized in either natural or artificialfractures, and the treating liquid may be injected in a previouslyfractured formation or may be injected simultaneously with the creationof the fracture.

When the treating liquid is injected into a formation prior to afracturing treatment, the fracturing fluid should have a fluid loss lessthan that of the treating liquid, and preferably have an effective Evalue (E less than 0.001.

Although it is generally preferred that the treating liquid be a lowviscosity liquid (Le. about 1 cp. or less), it can be appreciated thatconsiderably higher viscosity liquids may be used in highly permeableformations.

Broadly, the present invention relates to a new and improved method oftreating Wells for providing a continuing or prolonged treatmentthereof, namely paraflin control, corrosion inhibition, scaleprevention, bacteria control, well stimulation and similar problemsrequiring the injection of chemicals into a well.

What is claimed is:

1. A method of providing a desired type of a continuing or prolongedtreatment of a Well, comprising the step of: introducing into aproducing formation a desired treating liquid having a high fluid lossat a pressure sufliciently great to cause the treating liquid to enterthe formation and be substantially lost to a fracture face near the Wellbore, whereby said treating liquid is slowly produced back with the wellfluids; said high fluid loss liquid being one having an effective Evalue of a minimum of about 0.003 ft./n1in. wherein E is determined bythe following formula:

1 1 1 Esta es 12. 0.0469 diKAP/g. (ft./min.

=formation porosity K=formation permeability 6 =viscosity of injectedfluid AP=diflerential pressure C =reservoir fluid compressibility factor2. The method of claim 1 wherein the treating liquid is selected fromthe group consisting of a paraffin inhibiting agent, a corrosioninhibiting agent, a scale'deposition preventative agent, a surfaceactive agent, a bactericide, la chelating agent, and an emulsionbreaker.

3. A method of providing a predetermined type of a continuing orprolonged treatment of Well fluids produced from underground stratapenetrated by the bore of a well, comprising the steps of:

(a) introducing into the well a desired well treating liquid having ahigh fluid loss, said high fluid loss liquid being one having aneffective E value of a minimum of about 0.003 ft./min. wherein E isdetermined by the following formula:

eif

E =0.0469 /KAP/ i fa/mini (ft./1nin.

(b) causing said treating liquid to contact a section of the undergroundstrata to be fractured;

(c) applying sufficient pressure to said treating liquid to fracturesaid strata section and enter thereinto, whereby said treating liquid issubstantially lost to the face of the fracture and into the stratasection within the first few feet of the fracture;

(d) introducing into the well immediately after said treating liquid, atfracturing liquid having a fluid loss substantially less than that ofsaid treating liquid;

(e) causing said fracturing liquid to enter the section of theunderground strata previously fractured;

(f) applying sufiicient pressure to said fracturing liquid to extend thefracture into said strata section, enter thereinto and displace anytreating liquid not previously lost to the formation face, whereby saidfracturing liquid is extended substantially into the formation; and

(g) allowing the treating liquid to be produced back with the wellfluids thereby providing a continuing treatment of the well by thetreating liquid.

4. The method of claim 3 wherein the treating liquid is selected fromthe group consisting of a paraflin inhibiting agent, a corrosioninhibiting agent, a scale deposition preventative agent, a surfaceactive agent, a bactericide, a chelating agent, and an emulsion breaker.

5. A method of treating underground strata containing either a naturalor artificial fracture therein and penetrated by the bore of a well forproviding a desired c0ntinuing or prolonged treatment of the well,comprising the steps of:

(a) introducing into the well a desired well treating liquid having ahigh fluid loss, said high fluid loss liquid being one having aneffective E value of a minimum of about 0.003 ft./min. wherein E isdetermined by the following formula:

E. E. E;

E,: 0.0469V 5KAP/ (fr/mini 3,323,595 7 8 Where: 6. The method of claim 5wherein the treating liquid is selected from the group consisting of ap-araffin inhibiting agent, a corrosion inhibiting agent, a scaledeposition preventative agent, a surface active agent, a bac- 5tericide, a chelating agent, and an emulsion breaker.

=formation porosity K=formati0n permeability =visc0sity of injectedfluid AP=differential pressure C =reservoir fluid compressibility factorReferences Cited (b) causing said treating liquid to contact a sectionUNITED STATES PATENTS of the underground strata having a fracturetherein;

(0) applying sufficient pressure to said treating liquid 10 2,596,8445/1952 Clark 16622 to cause said liquid to enter said strata, wherebysaid 2,927,639 3/1960 Schuessler at 166 42 treating liquid issubstantially lost to the face of the 3,108,636 10/1963 Peterson 166-42fracture and into the strata section within the first 3,167,123 1/1965Graham et a1 16642 few feet of th fracture; and 3,199,591 8/1965 p y16642 ((1) allowing the treating liquid to be produced back 15 with thewell fluids thereby providing a continuing CHARLES O CONNELL Examme"treatment of the well by the treating liquid. STEPHEN J. NOVOSAD,Examiner.

1. A METHOD OF PROVIDING A DESIRED TYPE OF A CONTINUING OR PROLONGEDTREATMENT OF A WELL, COMPRISING THE STEP OF: INTRODUCING INTO APRODUCING FORMATION A DESIRED TREATING LIQUID HAVING A HIGH FLUID LOSSAT A PRESSURE SUFFICIENTLY GREAT TO CAUSE THE TREATING LIQUID TO ENTERTHE FORMATION AND BE SUBSTANTIALLY LOST TO A FRACTURE FACE NEAR THE WELLBORE, WHEREBY SAID TREATING LIQUID IS SLOWLY PRODUCED BACK